CA2842045A1 - System and method for production of reservoir fluids - Google Patents
System and method for production of reservoir fluids Download PDFInfo
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- CA2842045A1 CA2842045A1 CA2842045A CA2842045A CA2842045A1 CA 2842045 A1 CA2842045 A1 CA 2842045A1 CA 2842045 A CA2842045 A CA 2842045A CA 2842045 A CA2842045 A CA 2842045A CA 2842045 A1 CA2842045 A1 CA 2842045A1
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- 239000012530 fluid Substances 0.000 title claims abstract description 90
- 238000004519 manufacturing process Methods 0.000 title claims description 11
- 238000000034 method Methods 0.000 claims description 25
- 238000006073 displacement reaction Methods 0.000 claims description 21
- 239000007788 liquid Substances 0.000 abstract description 62
- 230000009977 dual effect Effects 0.000 abstract description 25
- 238000005086 pumping Methods 0.000 abstract description 7
- 230000002452 interceptive effect Effects 0.000 abstract description 2
- 238000002347 injection Methods 0.000 description 32
- 239000007924 injection Substances 0.000 description 32
- 210000002445 nipple Anatomy 0.000 description 11
- 230000008569 process Effects 0.000 description 10
- 238000013461 design Methods 0.000 description 7
- 230000005484 gravity Effects 0.000 description 7
- 238000005553 drilling Methods 0.000 description 5
- 239000011800 void material Substances 0.000 description 5
- 229930195733 hydrocarbon Natural products 0.000 description 4
- 150000002430 hydrocarbons Chemical class 0.000 description 4
- 230000000670 limiting effect Effects 0.000 description 4
- 238000011084 recovery Methods 0.000 description 4
- 230000000737 periodic effect Effects 0.000 description 3
- 230000002829 reductive effect Effects 0.000 description 3
- 238000000926 separation method Methods 0.000 description 3
- 241000364021 Tulsa Species 0.000 description 2
- 230000036961 partial effect Effects 0.000 description 2
- 230000037361 pathway Effects 0.000 description 2
- 230000000750 progressive effect Effects 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- 238000013022 venting Methods 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 239000000969 carrier Substances 0.000 description 1
- 238000007796 conventional method Methods 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000002349 favourable effect Effects 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 230000001788 irregular Effects 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
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- 238000011160 research Methods 0.000 description 1
- 230000002441 reversible effect Effects 0.000 description 1
- 238000007789 sealing Methods 0.000 description 1
Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
- E21B43/121—Lifting well fluids
- E21B43/122—Gas lift
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/18—Pipes provided with plural fluid passages
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimising the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimising the spacing of wells comprising at least one inclined or horizontal well
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- Mining & Mineral Resources (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
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- Environmental & Geological Engineering (AREA)
- Physics & Mathematics (AREA)
- Geochemistry & Mineralogy (AREA)
- Mechanical Engineering (AREA)
- Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
- Apparatus Associated With Microorganisms And Enzymes (AREA)
- Valves And Accessory Devices For Braking Systems (AREA)
- Prostheses (AREA)
- Jet Pumps And Other Pumps (AREA)
Abstract
An artificial lift system removes reservoir fluids from a wellbore. A gas lift system is disposed in a first tubing string anchored by a packer, and a downhole pump, or alternative plunger lift, may be positioned with a second tubing string. A dual string anchor may be disposed with the first tubing string to limit the movement of the second tubing string. The second tubing string may be removably attached with the dual string anchor with an on-off tool without disturbing the first tubing string. A one-way valve may also be used to allow reservoir fluids to flow into the first tubing string in one direction only. The second tubing string may be positioned within the first tubing string and the injected gas may travel down the annulus between the first and second tubing strings. A bi-flow connector may anchor the second string to the first string and allow reservoir liquids in the casing tubing annulus to pass through the connector to the downhole pump. Injected gas may be allowed to pass vertically through the bi- flow connector to lift liquids from below the downhole pump to above the downhole pump. The bi-flow connector prevents the downwardly injected gas from interfering with the reservoir fluids flowing through the bi-flow connector. In another embodiment, gas from the reservoir lifts reservoir liquids from below the downhole pump to above the downhole pump. A first tubing string may contain a downhole pumping system or alternative plunger lift above a packer assembly. A concentric tubing system below the packer may lift liquids using the gas from the reservoir.
Description
SYSTEM AND METHOD FOR PRODUCTION OF
RESERVOIR FLUIDS
CROSS-REFERENCE TO RELATED APPLICATIONS
100011 This application is a continuation-in-part of co-pending U.S.
Application No. 12/001,152 filed on December 10, 2007, which application is hereby incorporated by reference for all purposes in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR
DEVELOPMENT
[00021 N/A
REFERENCE TO MICROFICHE APPENDIX
[00031 N/A
BACKGROUND OF THE INVENTION
100041 1. Field of the Invention 100051 This invention relates to production systems and methods deployed in subterranean oil and gas wells.
100061 2. Description of the Related Art 100071 Many oil and gas wells will experience liquid loading at some point in their productive lives due to the reservoir's inability to provide sufficient energy to carry wellbore liquids to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or flow at a reduced rate. To increase or re-establish the production, operators place the well on artificial lift, which is defined as a method of removing wellbore liquids to the surface by applying a form of energy into the wellbore. Currently, the most common artificial lift systems in the oil and gas' industry are down-hole pumping systems, plunger lift systems, and compressed gas systems.
100081 The most popular form of down-hole pump is the sucker rod pump. It comprises a dual ball and seat assembly, and a pump barrel containing a plunger. A string of sucker rods connects the downhole pump to a pump jack at the surface. The pump jack at the surface provides the reciprocating motion to the rods which in turn provides the reciprocal motion to stroke the pump, which is a fluid displacement device. As the pump strokes, fluids above the pump are gravity fed into the pump chamber and are then pumped up the production tubing and out of the wellbore to the surface facilities. Other downhole pump systems include progressive cavity, jet, electric submersible pumps and others.
100091 A plunger lift system utilizes compressed gas to lift a free piston traveling from the bottom of the tubing in the wellbore to the surface. Most plunger lift systems utilize the energy from a reservoir by closing in the well periodically in order to build up pressure in the wellbore.
The well is then opened rapidly which creates a pressure differential, and as the plunger travels to the surface, it lifts reservoir liquids that have accumulated above the plunger. Like the pump, the plunger is also a tluid displacement device.
100101 Compressed gas systems can be either continuous or intermittent. As their names imply, continuous systems continuously inject gas into the wellbore and intermittent systems inject gas intennittently. In both systems, compressed gas flows into the casing-tubing annulus of the well and travels down the wellbore to a gas lift valve contained in the tubing string. If the gas pressure in the casing-tubing annulus is sufficiently high compared to the pressure inside the tubing adjacent to the valve, the gas lift valve will be in the open position which subsequently allows gas in the casing-tubing annulus to enter the tubing and thus lift liquids in the tubing out of the wellbore. Continuous gas lift systems work effectively unless the reservoir has a depletion or partial depletion drive, which results in a pressure decline in the reservoir as fluids are removed. When the reservoir pressure depletes to a point that the gas lift pressure causes significant back pressure on the reservoir, continuous gas lift systems become inefficient and the now rate from the well is reduced until it is uneconomic to operate the system. Intermittent gas lift systems apply this back pressure intermittently and therefore can operate economically for longer periods of time than continuous systems. [nteiiiiittent systems are not as common as continuous systems because of the difficulties and expense of operating surface equipment on an intermittent basis.
100111 Horizontal drilling was developed to access irregular fossil energy deposits in order to enhance the recovery of hydrocarbons. Directional drilling was developed to access fossil energy deposits some distance from the surface location of the wellbore.
Generally, both of these drilling methods begin with a vertical hole or well. At a certain point in this vertical well, a turn of the drilling tool is initiated which eventually brings the drilling tool into a deviated position with respect to the vertical position.
100121 It is not practical to install most artificial lift systems in the deviated sections of directional or horizontal wells or deep into the perforated section of vertical wells since down-hole equipment installed in these regions may be inefficient or can undergo high maintenance costs due to wear and/or solids and gas entrained in the liquids interfering with the operation of the pump. Therefore, most operators only install down-hole artificial lift equipment in the vertical portion of the wellbore above the reservoir. In many vertical wells with relatively long perforated intervals, many operators choose to not install artificial lift equipment in the well due to the factors above. Downhole pump systems, plunger lift systems, and compressed gas lift systems are not designed to recover any liquids that exist below the downhole equipment.
Therefore, in many vertical, directional, and horizontal wells, a column of liquid ranging from hundreds to many thousands of feet may exist below the down-hole artificial lift equipment.
Because of the limitations with current artificial lift systems, considerable hydrocarbon reserves cannot be recovered using conventional methods in depletion or partial depletion drive directional or horizontally drilled wells, and vertical wells with relatively long perforated intervals. Thus, a major problem with the current technology is that reservoir liquids located below conventional down-hole artificial lift equipment cannot be lifted.
100131 There is a need to provide an artificial lift system that will enable the recovery of liquids in the deviated sections of directional or horizontal wellbores, and in vertical wells with relatively long perforated intervals.
100141 There is a need to provide an artificial lift system that will enable the recovery of liquids in vertical wells with relatively long perforated intervals and in the deviated sections of directional and horizontal wellbores with smaller casing diameters.
100151 There is a need to lower the artificial lift point in vertical wells with relatively long perforated intervals and in wells with deviated or horizontal sections.
[0016J There is a need to provide a high velocity volume of injection gas to more efficiently sweep the reservoir liquids from the wellbore.
[00171 There is a need to provide a more efficient, less costly wellbore liquid removal process.
100181 There is a need for a less costly artificial lift method for vertical wells with relatively long perforated intervals and for wells with deviated or horizontal sections.
100191 There is a need for a less costly and more efficient artificial lift method for wells that still have sufficient reservoir energy and reservoir gas to lift liquids from below to above the downhole artificial lift equipment.
100201 Finally, there is a need to provide a more efficient gas and solid separation method to lower the lift point in wells with deviated and horizontal sections and for vertical wells with relatively long perforated intervals.
RESERVOIR FLUIDS
CROSS-REFERENCE TO RELATED APPLICATIONS
100011 This application is a continuation-in-part of co-pending U.S.
Application No. 12/001,152 filed on December 10, 2007, which application is hereby incorporated by reference for all purposes in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR
DEVELOPMENT
[00021 N/A
REFERENCE TO MICROFICHE APPENDIX
[00031 N/A
BACKGROUND OF THE INVENTION
100041 1. Field of the Invention 100051 This invention relates to production systems and methods deployed in subterranean oil and gas wells.
100061 2. Description of the Related Art 100071 Many oil and gas wells will experience liquid loading at some point in their productive lives due to the reservoir's inability to provide sufficient energy to carry wellbore liquids to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or flow at a reduced rate. To increase or re-establish the production, operators place the well on artificial lift, which is defined as a method of removing wellbore liquids to the surface by applying a form of energy into the wellbore. Currently, the most common artificial lift systems in the oil and gas' industry are down-hole pumping systems, plunger lift systems, and compressed gas systems.
100081 The most popular form of down-hole pump is the sucker rod pump. It comprises a dual ball and seat assembly, and a pump barrel containing a plunger. A string of sucker rods connects the downhole pump to a pump jack at the surface. The pump jack at the surface provides the reciprocating motion to the rods which in turn provides the reciprocal motion to stroke the pump, which is a fluid displacement device. As the pump strokes, fluids above the pump are gravity fed into the pump chamber and are then pumped up the production tubing and out of the wellbore to the surface facilities. Other downhole pump systems include progressive cavity, jet, electric submersible pumps and others.
100091 A plunger lift system utilizes compressed gas to lift a free piston traveling from the bottom of the tubing in the wellbore to the surface. Most plunger lift systems utilize the energy from a reservoir by closing in the well periodically in order to build up pressure in the wellbore.
The well is then opened rapidly which creates a pressure differential, and as the plunger travels to the surface, it lifts reservoir liquids that have accumulated above the plunger. Like the pump, the plunger is also a tluid displacement device.
100101 Compressed gas systems can be either continuous or intermittent. As their names imply, continuous systems continuously inject gas into the wellbore and intermittent systems inject gas intennittently. In both systems, compressed gas flows into the casing-tubing annulus of the well and travels down the wellbore to a gas lift valve contained in the tubing string. If the gas pressure in the casing-tubing annulus is sufficiently high compared to the pressure inside the tubing adjacent to the valve, the gas lift valve will be in the open position which subsequently allows gas in the casing-tubing annulus to enter the tubing and thus lift liquids in the tubing out of the wellbore. Continuous gas lift systems work effectively unless the reservoir has a depletion or partial depletion drive, which results in a pressure decline in the reservoir as fluids are removed. When the reservoir pressure depletes to a point that the gas lift pressure causes significant back pressure on the reservoir, continuous gas lift systems become inefficient and the now rate from the well is reduced until it is uneconomic to operate the system. Intermittent gas lift systems apply this back pressure intermittently and therefore can operate economically for longer periods of time than continuous systems. [nteiiiiittent systems are not as common as continuous systems because of the difficulties and expense of operating surface equipment on an intermittent basis.
100111 Horizontal drilling was developed to access irregular fossil energy deposits in order to enhance the recovery of hydrocarbons. Directional drilling was developed to access fossil energy deposits some distance from the surface location of the wellbore.
Generally, both of these drilling methods begin with a vertical hole or well. At a certain point in this vertical well, a turn of the drilling tool is initiated which eventually brings the drilling tool into a deviated position with respect to the vertical position.
100121 It is not practical to install most artificial lift systems in the deviated sections of directional or horizontal wells or deep into the perforated section of vertical wells since down-hole equipment installed in these regions may be inefficient or can undergo high maintenance costs due to wear and/or solids and gas entrained in the liquids interfering with the operation of the pump. Therefore, most operators only install down-hole artificial lift equipment in the vertical portion of the wellbore above the reservoir. In many vertical wells with relatively long perforated intervals, many operators choose to not install artificial lift equipment in the well due to the factors above. Downhole pump systems, plunger lift systems, and compressed gas lift systems are not designed to recover any liquids that exist below the downhole equipment.
Therefore, in many vertical, directional, and horizontal wells, a column of liquid ranging from hundreds to many thousands of feet may exist below the down-hole artificial lift equipment.
Because of the limitations with current artificial lift systems, considerable hydrocarbon reserves cannot be recovered using conventional methods in depletion or partial depletion drive directional or horizontally drilled wells, and vertical wells with relatively long perforated intervals. Thus, a major problem with the current technology is that reservoir liquids located below conventional down-hole artificial lift equipment cannot be lifted.
100131 There is a need to provide an artificial lift system that will enable the recovery of liquids in the deviated sections of directional or horizontal wellbores, and in vertical wells with relatively long perforated intervals.
100141 There is a need to provide an artificial lift system that will enable the recovery of liquids in vertical wells with relatively long perforated intervals and in the deviated sections of directional and horizontal wellbores with smaller casing diameters.
100151 There is a need to lower the artificial lift point in vertical wells with relatively long perforated intervals and in wells with deviated or horizontal sections.
[0016J There is a need to provide a high velocity volume of injection gas to more efficiently sweep the reservoir liquids from the wellbore.
[00171 There is a need to provide a more efficient, less costly wellbore liquid removal process.
100181 There is a need for a less costly artificial lift method for vertical wells with relatively long perforated intervals and for wells with deviated or horizontal sections.
100191 There is a need for a less costly and more efficient artificial lift method for wells that still have sufficient reservoir energy and reservoir gas to lift liquids from below to above the downhole artificial lift equipment.
100201 Finally, there is a need to provide a more efficient gas and solid separation method to lower the lift point in wells with deviated and horizontal sections and for vertical wells with relatively long perforated intervals.
BRIEF SUMMARY OF THE INVENTION
100211 A gas assisted downhole system is disclosed, which is an artificial lift system designed to recover by-passed hydrocarbons in directional, vertical and horizontal wellbores by incorporating a dual tubing arrangement. In one embodiment, a first tubing string contains a gas lift system, and a second tubing string contains a downhole pumping system. In the first tubing string, the gas lift system, which is preferably intermittent, is utilized to lift reservoir fluids from below the downhole pump to above a packer assembly where the fluids become trapped. As more reservoir fluids are added above the packer, the fluid level rises in the casing annulus above the downhole pump installed in the adjacent second tubing string, and the trapped reservoir fluids are pumped to the surface by the downhole pump. In another embodiment, the second tubing string contains a downhole plunger system. As reservoir fluids are added above the packer, the fluid level rises in the casing annulus above the downhole plunger installed in the adjacent second tubing string, and the trapped reservoir fluids are lifted to the surface by the downhole plunger system.
100221 A dual string anchor may be disposed with the first tubing string to limit the movement of the second tubing string. The second tubing string may be removably attached with the dual string anchor with an on-off tool without disturbing the first tubing string.
A one-way valve may also be used to allow reservoir fluids to flow into the first tubing string in one direction only. The one way valve may be placed in the first tubing string below the packer to allow trapped pressure below the packer to be released into the first tubing string. The valve provides a pathway to the surface for the gas trapped below the packer. The resulting reduced back pressure on the reservoir may lead to production increases.
[00231 In another embodiment, the second tubing string may be within the first tubing string, and the injected gas may travel down the annulus between the first and second tubing strings.
The second string may house a fluid displacement device, such as a downhole pumping system or a plunger lift system. A bi-flow connector may anchor the second string to the first string and allow reservoir liquids in the casing tubing annulus to pass through the anchor to the downhole pump. In one embodiment, the bi-flow connector may be a cylindrical body having a thickness, a first end, a second end, a central bore from the first end to said second end, and a side surface.
A first channel may be disposed through the thickness from the first end to the second end. A
second channel may be disposed through the thickness from the side surface to the central bore, with the first channel and second channel not intersecting. Injected gas may be allowed to pass vertically through the bi-flow connector to lift liquids from below the downhole pump to above the downhole pump. The bi-flow connector prevents the injected gas from contacting the reservoir liquids flowing through the bi-flow connector. Also contemplated are multiple channels in addition to the first channel and multiple channels in addition to the second channel.
100241 In yet another embodiment, gas from the reservoir lifts reservoir liquids from below the fluid displacement device, such as a downhole pump or a plunger, to above the fluid displacement device. A first tubing string may contain the fluid displacement device above a packer assembly. A blank sub may be positioned between an upper perforated sub and a lower perforated sub in the first tubing string below the fluid displacement device.
A second tubing string within the first tubing string and located below the lower perforated sub may lifts liquids using the gas from the reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS
100251 For a further understanding of the nature and objects of the present invention, reference is had to the following figures in which like parts are given like reference numerals and wherein:
[00261 FIG. 1 depicts a directional or horizontal wellbore installed with a conventional rod pumping system of the prior art.
100271 FIG. 2 depicts a conventional gas lift system in a directional or horizontal wellbore of the prior art.
[00281 FIG. 3 depicts an embodiment of the invention utilizing a rod pump and a gas lift system.
[00291 FIG. 4 depicts another embodiment of the invention similar to FIG. 3 except with no internal gas lift valve.
100301 FIG. 5 depicts yet another embodiment of the invention having a Y
block.
100311 FIG. 6 depicts another embodiment of the invention similar to FIG. 5 except with no internal gas lift valve.
100321 FIG. 7 depicts another embodiment similar to FIG. 3, except with a dual string anchor and an on-off tool.
[00331 FIG. 8 depicts another embodiment similar to FIG. 7, except with no internal gas lift valve.
100341 FIG. 9 depicts another embodiment similar to FIG. 7, except with a one-way valve.
100351 FIG. 10 is the embodiment of FIG. 9, except shown in a completely vertical wellbore.
100361 FIG. 11 is an embodiment similar to FIG. 11, except that an alternative embodiment plunger lift system is installed in place of the downhole pump system, and with no surface tank and no dual string anchor.
[00371 FIG. 12 depicts another embodiment in a vertical wellbore utilizing a bi-flow connector.
[00381 FIG. 13 is the embodiment of Fig 12 except in a horizontal wellbore.
[0039] FIG. 13A is an isometric view of a bi-flow connector.
100401 FIG. 13B is a section view along line 13A-13A of FIG. 13.
100411 FIG. 13C is a top view of FIG. 13A.
100421 FIG. 13D is a section view similar to FIG. 13B except with the bi-flow connector threadably attached at a first end with a first tubular and at a second end with a second tubular.
100431 FIG. 14 is the embodiment of Fig 13 except that an alternative embodiment plunger lift system is installed in place of the downhole pump system.
100441 FIG. 15 depicts another embodiment that utilizes gas that emanates from the reservoir to lift liquids from the curved or horizontal section of the wellbore.
100451 FIG. 16 is the embodiment of Fig 15 except it is shown in a vertical wellbore.
100461 FIG. 17 is the embodiment of Fig 16 except that an alternative embodiment plunger lift system is installed in place of the downhole pump system.
DETAILED DESCRIPTION OF THE INVENTION
100471 FIG. 1 shows one example of a conventional rod pump system of the prior art in a directional or horizontal wellbore. As set out in FIG. 1, tubing 1, which contains pumped liquids 13 is mounted inside a casing 6. A pump 5 is connected at the end of tubing 1 in a seating nipple 48 nearest the reservoir 9. Sucker rods 11 are connected from the top of pump 5 and continue vertically to the surface 12. Casing 6, cylindrical in shape, surrounds and may be coaxial with tubing 1 and extends below tubing 1 and pump 5 on one end and extends vertically to surface 12 on the other end. Below casing 6 is curve 8 and lateral 10 which is drilled through reservoir 9.
100481 The process is as follows: reservoir fluids 7 are produced from reservoir 9 and enter lateral 10, rise up curve 8 and casing 6. Because reservoir fluids 7 are usually multiphase, they separate into annular gas 4 and liquids 17. Annular gas 4 separates from reservoir fluids 7 and rises in annulus 2, which is the void space formed between tubing 1 and casing 6. The annular gas 4 continues to rise up annulus 2 and then flows out of the well to the surface 12. Liquids 17 enter pump 5 by the force of gravity from the weight of liquids 17 above pump 5 and enter pump to become pumped liquids 13 which travel up tubing 1 to the surface 12. Pump 5 is not considered to be limiting, but may be any down-hole pump or pumping system, such as a progressive cavity, jet pump, or electric submersible, and the like.
100491 FIG. 2 shows one example of a conventional gas lift system of the prior art in a directional or horizontal wellbore. Referring to FIG. 2, inside the casing 6, is tubing 1 connected to packer 14 and conventional gas lift valve 22. Below casing 6 is curve 8 and lateral 10 which is drilled through reservoir 9. The process is as follows: reservoir fluids 7 from reservoir 9 enter lateral 10 and rise up curve 8 and casing 6 and enter tubing 1. The packer 14 provides pressure isolation which allows annulus 2, which is formed by the void space between casing 6 and tubing 1, to increase in pressure from the injection of injection gas 16. Once the pressure increases sufficiently in annulus 2, conventional gas lift valve 22 opens and allows injection gas 16 to pass from annulus 2 into tubing 1, which then commingles with reservoir fluids 7 to become commingled fluids 18. This lightens the fluid column and commingled fluids 18 rise up tubing 1 and then flow out of the well to surface 12.
100501 FIG. 3 shows an embodiment utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore. Referring to FIG. 3, inside casing 6, is tubing 1 which begins at surface 12 and contains internal gas lift valve 15, bushing 25, and inner tubing 21. Inner tubing 21 may be within tubing 1, such as concentric. Bushing 25 may be a section of pipe whose purpose is to threadingly connect pipe joints using both its outer diameter and its inner diameter.
Bushing 25 may have pipe threads at one or both ends of its outer diameter, and pipe threads at one or both ends of its inner diameter. Other types of bushings and connection means are also contemplated. Tubing 1 is sealing,ly engaged to packer 14. Tubing 1 and inner tubing 21 extend below packer 14 through curve 8 and into lateral 10, which is drilled through reservoir 9. Inside casing 6 and adjacent to tubing 1 is tubing 3, which contains sucker rods 11 connected to pump 5. Pump 5 is connected to the end of tubing 3 by seating nipple 48. Tubing 3 is not sealingly engaged to packer 14.
100511 The process may be as follows: reservoir fluids 7 enter lateral 10 and enter tubing I. The reservoir fluids 7 are commingled with injection gas 16 to become commingled fluids 18 which rise up chamber annulus 19, which is the void space formed between inner tubing 21 and tubing I. The commingled fluids 18 then exit through the holes in perforated sub 24.
Commingled gas 41 separates from commingled fluids 18 and rises in annulus 2, which is formed by the void space between casing 6 and tubing 1 and tubing 3. Commingled gas 41 then enters tlow line 30 at the surface 12 and enters compressor 38 to become compressed gas 33, and travels through flow line 31 to surface tank 34. The compressor 38 is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline.
[00521 Compressed gas 33 then travels through flow line 32 which is connected to actuated valve 35. This actuated valve 35 opens and closes depending on either time or pressure realized in surface tank 34. When actuated, valve 35 opens, compressed gas 33 tlows through actuated valve 35 and travels through flow line 32 and into tubing 1 to become injection gas 16. The injection gas 16 travels down tubing 1 to internal gas lift valve 15, which is normally closed thereby preventing the flow of injection gas 16 down tubing 1. A sufficiently high pressure in tubing 1 above internal gas lift valve 15 opens internal gas lift valve 15 and allows the passage of injection gas 16 through internal gas lift valve 15. The injection gas 16 then enters the inner tubing 21, and eventually commingles with reservoir fluids 7 to become commingled fluids 18, and the process begins again. Liquids 17 and commingled gas 41 separate from the commingled tluids 18 and liquids 17 fall in annulus 2 and are trapped above packer 14.
Commingled gas 41 rises up annulus 2 as previously described. As more liquids 17 are added to annulus 2, liquids 17 rise above and are gravity fed into pump 5 to become pumped liquids 13 which travel up tubing 3 to surface 12.
100531 FIG. 4 shows an alternate embodiment similar to the design in FIG. 3 except that it does not utilize the internal gas lift valve 15.
100541 FIG. 5 shows yet another alternate embodiment utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore with a different downhole configuration from FIG. 3.
Referring to FIG. 5, inside the casing 6 is tubing 1 which contains an internal gas lift valve 15 and is sealingly engaged to packer 14. Packer 14 is preferably a dual packer assembly and is connected to Y block 50 which in turn is connected to chamber outer tubing 55.
Chamber outer tubing 55 continues below casing 6 through curve 8 and into lateral 10 which is drilled through reservoir 9. Inner tubing 21 is secured by chamber bushing 22 to one of the tubular members of Y Block 50 leading to lower tubing section 37. Inner tubing 21 may be concentric with chamber outer tubing 55. The inner tubing 21 extends inside of Y block 50 and chamber outer tubing 55 through the curve 8 and into the lateral 10. The second tubing string arrangement comprises a lower section 37 and an upper section 36. The lower section 37 comprises a perforated sub 24 connected above a one way valve 28 and is then sealingly engaged in the packer 14.
10055] Perforated sub 24 is closed at its upper end and is connected to the upper tubing section 36. Upper tubing section 36 comprises a gas shroud 58, a perforated inner tubular member 57, a cross over sub 59 and tubing 3 which contains pump 5 and sucker rods 11. The gas shroud 58 is tubular in shape and is closed at its lower end and open at its upper end. It surrounds perforated inner tubular member 57, which extends above gas shroud 58 to crossover sub 59 and connects to the tubing 3, which continues to the surface 12. Above the crossover sub 59, and contained inside of tubing 3 at its lower end, is pump 5 which is connected to sucker rods 11, which continue to the surface 12. Annular gas 4 travels up annulus 2 into flowline 30 which is connected to compressor 38 which compresses annular gas 4 to become compressed gas 33. The compressor 38 is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline.
100561 Compressed gas 33 flows through flowline 31 to surface tank 34 which is connected to a second flowline 32 that is connected to actuated valve 35. This actuated valve 35 opens and closes depending on either time or pressure realized in surface tank 34. When actuated valve 35 opens, compressed gas 33 flows through actuated valve 35 and travels through flowline 32 and into tubing 1 to become injection gas 16. The injection gas 16 travels down tubing 1 to internal gas lift valve 15, which is normally closed thereby preventing the flow of injection gas 16 down tubing 1. A sufficiently high pressure in tubing 1 above internal gas lift valve 15 opens internal gas lift valve 15 and allows the passage of injection gas 16 through internal gas lift valve 15, through Y Block 50 and into chamber annulus 19, which is the void space between inner concentric tubing 21 and chamber outer tubing 55. Injection gas 16 is forced to flow down chamber annulus 19 since its upper end is isolated by chamber bushing 25.
Injection gas 16 displaces the reservoir fluids 7 to become commingled fluids 18 which travel up the inner concentric tubing 21.
[00571 Commingled fluids 18 travel out of inner concentric tubing 21 into one of the tubular members of Y Block 50, through packer 14 and standing valve 28, and then through the perforated sub 24 into annulus 2, where the gas separates and rises to become annular gas 4 to continue the cycle. The liquids 17 separate from the commingled fluids 18 and fall by the force of gravity and are trapped in annulus 2 above packer 14 and are prevented from flowing back into perforated sub 24 because of standing valve 28. As liquids 17 accumulate in annulus 2, they rise above pump 5 and are forced by gravity to enter inside of gas shroud 58 and into perforated tubular member 57 where they travel up cross-over sub 59 to enter pump 5 where they become pumped liquids 13 and are pumped up tubing 3 to the surface 12.
100581 FIG. 6 shows an alternate embodiment of the invention similar to the design in FIG. 5 except that it does not utilize the internal gas lift valve 15.
100591 FIG. 7 shows an alternate embodiment similar to FIG. 3, except that there is a downhole anchor assembly or dual string anchor 20 disposed with first tubing string 1 and installed and attached with second tubing string with on-off tool 26. Referring to FIG. 7, first tubing string 1 is inside casing 6. First tubing string 1 begins at the surface 12 and contains internal gas lift valve IS, bushing 25, perforated sub 24, and inner tubing 21. Perforated sub 24 is available from Weatherford International of Houston, Texas, among others. Tubing 1 is engaged to dual string anchor 20 and continues through it and is engaged to packer 14 and extends through it. Inner tubing 21 connects to bushing 25 and continues through perforated sub 24, dual string anchor 20, packer 14 and terminates prior to the end of tubing 1. Dual string anchor 20 is available from Kline Oil Tools of Tulsa, Oklahoma, among others. Other types of dual string anchors 20 are also contemplated. Inner tubing 21 may be within tubing 1. Tubing 1 extends through and below dual string anchor 20 and through and below packer 14 through curve 8 and into lateral 10, which is drilled through reservoir 9. Second tubing string 3 is inside casing 6 and adjacent to first tubing string 1. Second tubing string 3 contains perforated sub 23, sucker rods 11, pump 5, seating nipple 48, and on-off tool 26. Second tubing string 3 may be selectively engaged to dual string anchor 20 with on-off tool 26. On-off tool 26 is available from D&L Oil Tools of Tulsa, Oklahoma and from Weatherford International of Houston, Texas, among others.
Other types of on-off tool 26 and attachment means are also contemplated. On-off tool 26 may be disposed with perforated sub 23, which may be attached with second tubing string 3.
100601 The process for FIG. 7 is similar to that for FIG. 3. The dual string anchor 20 functions to immobilize the second tubing string 3 by supporting it with first tubing string 1.
Immobilization is important, since in deeper pump applications, the mechanical pump 5 may induce movement to second tubing string 3 which may in turn cause wear on the tubulars.
Movement may also cause the mechanical pump operation to cease or become inefficient. On-off tool 26 allows the second tubing string 3 to be selectively connected or disconnected from the dual string anchor 20 without disturbing the first tubing string 1. The dual string anchor 20 minimizes inefficiencies in the pump and costly workovers to repair wear on the tubing strings.
This movement is caused by the movement induced upon the second tubing string by the downhole pumping system.
[00611 FIG. 8 shows another alternate embodiment similar to the design in FIG.
7 except that it does not utilize internal gas lift valve 15.
100621 FIG. 9 shows another alternate embodiment similar to the design of FIG.
7, except that FIG. 9 includes one-way valve 28 disposed on first tubing string 1 below packer 14. Referring to FIG. 9, when pressure conditions are favorable, one-way valve 28 opens to allow reservoir gas 27 to pass into chamber annulus 19. One-way valve 28 may be a reverse flow check valve available from Weatherford International of Houston, Texas, among others.
Other types of one-way valves 28 are also contemplated. Although only one one-valve 28 is shown, it is contemplated that there may be more than one one-way valve 28 for all embodiments. One-way valve 28 may be threadingly disposed with a carrier such as a conventional tubing retrievable mandrel or a gas lift mandrel. Other connection types, carriers, and mandrels are also contemplated.
[00631 One-way valve 28 functions to allow fluids to flow from outside to inside the device in one direction only. In FIGS. 9-14, one-way valve 28 may be placed in the first tubing string 1 below the packer 14 to vent trapped pressure below the packer 14 into the first tubing string 1.
In a vertical well application, this venting may assist the optimum functioning of the artificial lift system. One-way valve 28 has at least two functions: (1) it provides a pathway to the surface for reservoir gas 27 trapped below packer 14, and (2) it leads to production increases by reducing back pressure on the reservoir. As can now be understood, one-way valve 28 may be positioned at a location on first tubing string 1, such as below packer 14, that is different than the location where injected gas 16 initially commingles with the reservoir fluids where inner tubing 21 ends.
Injected gas 16 may initially commingle with reservoir fluids 7 at a first location, and one-way valve 28 may be disposed on first tubing string 1 at a second location. One-way valve 28 may be disposed above reservoir 9, although other locations are contemplated. One-way valve 28 allows the venting of trapped fluids, and allows flow in only one direction.
100641 FIG. 10 shows the embodiment of FIG. 9 in a completely vertical wellbore.
[00651 As can now be understood, dual string anchor or dual tubing anchor 20 with on-off tool 26 and one way-valve 28 may be used independently, together, or not at all.
For all embodiments in deviated, horizontal, or vertical wellbore applications, there may be (1) gas lift valve 15, dual string anchor 20, and one-way valve 28 below packer 14, (2) no gas lift valve 15, no dual string anchor 20, and no one-way valve 28 below packer 14, or (3) any combination or permutation of the above. Surface tank 34 and actuated valve 35 are also optional in all the embodiments.
[00661 FIG. 11 is an embodiment similar to FIG 10 in which pump 5 and sucker rods 11 have been replaced with an alternative embodiment plunger lift system, and there is no surface tank 34 and no one-way valve 28. Referring to FIG 11, the process is as follows.
Initially, actuated valve 37 is open at surface 12, which allows flow from tubing 3 to surface 12.
Actuated valve 35 is open and actuated valve 36 is closed. Supply gas 46, which may emanate from the well or a pipeline, is compressed by compressor 38 and compressed gas 33 flows through flow line 31, through actuated valve 35 and flow line 32, and into tubing Ito become injection gas 16, which then flows down tubing 1, through gas lift valve 15, and through inner tubing 21. At the end of inner tubing 21, injection gas 16 combines with reservoir fluids 7 to become commingled fluids 18, which rise up chamber annulus 19 and flow through perforated sub 24 into annulus 2.
Liquids 17 fall to the bottom of annulus 2.
10067J As more liquids are added in annulus 2, they eventually rise above plunger 5 and into tubing 3 and rise above perforated sub 24, which may cause the injection pressure to rise which signals actuated valve 35 to close, actuated valve 39 to open, and actuated valve 37 to close.
Compressed gas 33 then flows through actuated valve 36 and through flow line 30, and into annulus 2 to become injection gas 16. When a sufficient volume of injection gas 16 has been added to annulus 2, the pressure in annulus 2 rises sufficiently to signal actuated valve 37 to open, actuated valve 36 to close, and actuated valve 35 to open. The pressure differential lifts plunger 45 off of seating nipple 48 and rises up tubing 3 and pushes liquids 17 to surface 12.
Some injection gas 16 also flows to surface 12 via tubing 3. Once the pressure on tubing 3 drops sufficiently, plunger 45 falls back down to seating nipple 48 and the process begins again. Other sequences of the timing of the opening and closing of the actuated valves are contemplated.
Surface tank 34 may also be utilized.
[0068J FIG. 12 is another embodiment and utilizes an outer and inner tubing arrangement, such as concentric, incorporating a novel bi-flow connector 43 in a vertical wellbore. The bi- flow connector 43 is shown in detail in FIGS. 13A-13D and discussed in detail below. FIGS. 13 is similar to FIG. 12 except in a horizontal wellbore. Although FIG. 13 is discussed below, the discussion applies equally to FIG. 12. In FIG. 13, first tubing string 1 begins at surface 12 and is installed inside casing 6, contains bi-flow connector 43, bushing 25, one way valve 29, and is sealingly engaged to packer 14. Mud anchor 40 may be connected to bi-flow connector 43 to act as a reservoir for particulates that fall out of liquids 17, and to isolate the injection gas 16 from liquids 17. Mud anchor 40 is a tubing with one end closed and one end open, and is available from Weatherford International of Houston, Texas, among others. First tubing string 1 continues below packer 14 and contains one way valve 28 and continues until it terminates in curve 8 or lateral 10, or for FIG. 12 in or below reservoir 9. Within first tubing string 1 is second tubing string 21, which is also sealingly engaged to bushing 25 and continues down through packer 14 and may terminate prior to the end of first tubing string I. Third tubing string 3 is within first tubing string, and begins at surface 12 and terminates in on-off tool 26. On-off tool 26 allows third tubing string 3 to be selectively engaged to first tubing string 1. On-off tool 26 is sealingly engaged to bi-flow connector 43. Contained inside first tubing string 3 are sucker rods 11, pump and seating nipple 48. Sucker rods 11 are connected to pump 5 which is selectively engaged into seating nipple 48. Seating nipple 48 is available from Weatherford International of Houston, Texas, among others.
100691 As shown in FIGS. 13A-13D, bi-tlow connector 43 is a cylindrically shaped body with a central bore 112 extending from a first end 105 to a second end 107 and having a thickness 109.
Vertical or first channels 102 pass through the thickness 109 of the bi-flow connector 43 from the first end 105 to the second end 107. Horizontal or second channels 100 pass from the side surface 111 through the thickness 109 of the bi-flow connector 43 to the central bore 112.
Although shown vertical and horizontal, it is also contemplated that first channels may not be vertical and second channels may not be horizontal. Different numbers and orientations of channels are contemplated. The first channels 102 and second channels 100 do not intersect.
Threads 104, 108 are on the side surface 111 of the bi-flow connector 43 adjacent its first and second ends 105, 107. There may also be inner threads 106, 110 on the inner surface of the central bore 112 adjacent the first and second ends. As shown in FIGS. 12-13, the mud anchor 40 is attached with the inner threads 110, and the first tubing string 1 is attached with the outer threads 104, 108. In FIG. 13D, the threaded connection between the bi-flow connector 43 between upper tubular 114 and lower tubular 116 is similar to the connection in FIG. 13 between the hi-flow connector 43 and first tubing string I.
[00701 Returning to FIG. 13, the process may be as follows. Injection gas 16 travels down annulus 47 and passes vertically through bi-flow connector 43 and continues down through bushing 25, packer 14, second tubing string 21 and out into first tubing string 1 where it commingles with reservoir fluids 7 to become commingled fluids 18. Reservoir gas emanates from reservoir 9 and may travel through one way valve 28 and become part of commingled fluids 18, which rise up annulus 19 and travel through one way valve 29 and then separate into liquids 17 and commingled gas 41. Liquids 17 may enter horizontally through hi-flow connector 43 and up to pump 5 where they become pumped liquids 13 and are pumped to surface 12.
Commingled gas 41 rises up annulus 2 to surface 12.
100711 As can now be understood, the bi-flow connector 43 allows downward injection gas to pass vertically through the tool, while simultaneously allowing reservoir liquids to pass horizontally through the tool, without commingling the reservoir liquids with the downwardly flowing injection gas. The bi-flow connector 43 also allows the inner tubing string, such as third tubing string 3, to be selectively engaged to the outer tubing string, such as first tubing string 1.
The bi-flow connector 43 may be used in small casing diameter wellbores in which the installation of two side by side or adjacent tubing strings is impractical or impossible. The bi-tlow connector 43 is advantageous to wells that have a smaller diameter casing. Other non-concentric tubing arrangement embodiments may require larger casing sizes. A
plunger system is also contemplated in place of the downhole pump.
100721 FIG. 14 is the same embodiment as FIG. 13 except that an alternative embodiment plunger lift system is installed in place of the downhole pump system. A pump and a plunger are both fluid displacement devices.
100731 FIG. 15 is another embodiment using only reservoir gas to lift the reservoir liquids from below the downhole pump to above the downhole pump. This embodiment is similar to FIG. 13, but no inner tubing, such as third tubing string 3, is needed to house the downhole pump and no external injection gas is needed. It may also incorporate a one way valve 28 in the tubing string to prevent wellbore liquids from falling back down the wellbore. The one way valve 28 allows the liquids to be trapped above the packer until the pump can lift them to the surface. The smaller diameter of the inner tubing efficiently lifts reservoir fluids by forcing the reservoir gas into a smaller cross-sectional area whereby the gas is not allowed to rise faster than the reservoir liquids. Due to the smaller tubing size, a relatively small amount of reservoir gas can lift reservoir liquids the relatively short distance from the end of the tubing to the one way valve.
100741 Referring to FIG. 15, first tubing string 1 begins at surface 12 and contains seating nipple 48, upper perforated sub 23, blank sub 42, lower perforated sub 24, one way valve 39, on-off tool 26, packer 14, bushing 25 and terminates in curve 8 or lateral 10. Seating nipple 48, blank sub 42, perforated subs 23, 24, on-off tool 26, packer 14, one way valve 39, and bushing 25 are all available from Weatherford International of Houston, Texas, among others.
Connected to seating nipple 48 is pump 5 which is connected to sucker rods 11 which continue up to surface 12. Connected to bushing 25 is second tubing string 21 which is connected to one way valve 28, and continues down the wellbore and may terminate prior to the end of tubing 1.
[00751 The process may be as follows. Reservoir fluids 7 emanate from reservoir 9 and enter lateral 10 and then enter first tubing string 1 and second tubing string 21.
Gas in reservoir fluids 7 expand inside second tubing string 21 and lift reservoir fluids 7 up and out of second tubing string 21 into first tubing string 1, through on-off tool 26, through one way valve 39 and out of lower perforated sub 24 and into annulus 2. Reservoir fluids 7 separate into liquids 17 and annular gas 4. Liquids 17 enter into upper perforated sub 23 and then enter into pump 5 where they become pumped liquids 13 and are pumped to surface 12 via tubing 1.
Annular gas 4 rises up annulus 2 to surface 12.
100761 FIG. 16 is the embodiment of FIG. 15 except in a vertical wellbore.
100771 FIG. 17 is the embodiment of FIG. 16 except that a plunger has been installed in place of the sucker rods and pump. The plunger may be operated merely by the periodic opening and closing of the first tubing string 1 to the surface or it may be operated by the periodic or continuous injection of gas down the annulus combined with the periodic opening and closing of the first tubing string 1 to the surface. Both methods will force the plunger and liquids above it to the surface. This embodiment is much less expensive than installing a downhole pump. This design is advantageous for wells that have sufficient reservoir energy and gas production to lift liquids from below the downhole pump to above the downhole pump, yet still require artificial lift equipment to lift these liquids to the surface. This embodiment is less costly to install since no injection gas from the surface is required. Subsequently there is no gas injection tubing, no surface tank, no actuated valve, no compressor, and no dual string anchor. It will also accommodate wellbores with smaller casing diameters.
[00781 The embodiment of FIGS. 15-16 is advantageous for wells that have sufficient reservoir energy and gas production to lift liquids from below the downhole pump to above the downhole pump, yet still require artificial lift equipment to lift these liquids to the surface. This embodiment is less costly to install since no injection gas from the surface is required. There does not have to be any gas injection tubing, surface tank, actuated valve, compressor, or dual string anchor. It will also accommodate wellbores with smaller casing diameters. The embodiment of FIG. 17 is even less expensive because there does not have to be any downhole pump and related equipment.
100791 An advantages of all embodiments is a lower artificial lift point and better recovery of hydrocarbons. There is better gas and particulate separation in all embodiments. In FIGS. 3-11, the entry point for the commingled fluids is above the intake of the pump or other fluid displacement device, which helps break out any gas in the fluids since gravity will segregate the gas from the liquids. The same is true for particulates since there is a large reservoir for them to collect in below the pump. In FIGS. 12-17, the gas is discouraged from entering the perforated subs because of gravity separation.
100801 Because many varying and different embodiments may be made within the scope of the invention concept taught herein which may involve many modifications in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense.
100211 A gas assisted downhole system is disclosed, which is an artificial lift system designed to recover by-passed hydrocarbons in directional, vertical and horizontal wellbores by incorporating a dual tubing arrangement. In one embodiment, a first tubing string contains a gas lift system, and a second tubing string contains a downhole pumping system. In the first tubing string, the gas lift system, which is preferably intermittent, is utilized to lift reservoir fluids from below the downhole pump to above a packer assembly where the fluids become trapped. As more reservoir fluids are added above the packer, the fluid level rises in the casing annulus above the downhole pump installed in the adjacent second tubing string, and the trapped reservoir fluids are pumped to the surface by the downhole pump. In another embodiment, the second tubing string contains a downhole plunger system. As reservoir fluids are added above the packer, the fluid level rises in the casing annulus above the downhole plunger installed in the adjacent second tubing string, and the trapped reservoir fluids are lifted to the surface by the downhole plunger system.
100221 A dual string anchor may be disposed with the first tubing string to limit the movement of the second tubing string. The second tubing string may be removably attached with the dual string anchor with an on-off tool without disturbing the first tubing string.
A one-way valve may also be used to allow reservoir fluids to flow into the first tubing string in one direction only. The one way valve may be placed in the first tubing string below the packer to allow trapped pressure below the packer to be released into the first tubing string. The valve provides a pathway to the surface for the gas trapped below the packer. The resulting reduced back pressure on the reservoir may lead to production increases.
[00231 In another embodiment, the second tubing string may be within the first tubing string, and the injected gas may travel down the annulus between the first and second tubing strings.
The second string may house a fluid displacement device, such as a downhole pumping system or a plunger lift system. A bi-flow connector may anchor the second string to the first string and allow reservoir liquids in the casing tubing annulus to pass through the anchor to the downhole pump. In one embodiment, the bi-flow connector may be a cylindrical body having a thickness, a first end, a second end, a central bore from the first end to said second end, and a side surface.
A first channel may be disposed through the thickness from the first end to the second end. A
second channel may be disposed through the thickness from the side surface to the central bore, with the first channel and second channel not intersecting. Injected gas may be allowed to pass vertically through the bi-flow connector to lift liquids from below the downhole pump to above the downhole pump. The bi-flow connector prevents the injected gas from contacting the reservoir liquids flowing through the bi-flow connector. Also contemplated are multiple channels in addition to the first channel and multiple channels in addition to the second channel.
100241 In yet another embodiment, gas from the reservoir lifts reservoir liquids from below the fluid displacement device, such as a downhole pump or a plunger, to above the fluid displacement device. A first tubing string may contain the fluid displacement device above a packer assembly. A blank sub may be positioned between an upper perforated sub and a lower perforated sub in the first tubing string below the fluid displacement device.
A second tubing string within the first tubing string and located below the lower perforated sub may lifts liquids using the gas from the reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS
100251 For a further understanding of the nature and objects of the present invention, reference is had to the following figures in which like parts are given like reference numerals and wherein:
[00261 FIG. 1 depicts a directional or horizontal wellbore installed with a conventional rod pumping system of the prior art.
100271 FIG. 2 depicts a conventional gas lift system in a directional or horizontal wellbore of the prior art.
[00281 FIG. 3 depicts an embodiment of the invention utilizing a rod pump and a gas lift system.
[00291 FIG. 4 depicts another embodiment of the invention similar to FIG. 3 except with no internal gas lift valve.
100301 FIG. 5 depicts yet another embodiment of the invention having a Y
block.
100311 FIG. 6 depicts another embodiment of the invention similar to FIG. 5 except with no internal gas lift valve.
100321 FIG. 7 depicts another embodiment similar to FIG. 3, except with a dual string anchor and an on-off tool.
[00331 FIG. 8 depicts another embodiment similar to FIG. 7, except with no internal gas lift valve.
100341 FIG. 9 depicts another embodiment similar to FIG. 7, except with a one-way valve.
100351 FIG. 10 is the embodiment of FIG. 9, except shown in a completely vertical wellbore.
100361 FIG. 11 is an embodiment similar to FIG. 11, except that an alternative embodiment plunger lift system is installed in place of the downhole pump system, and with no surface tank and no dual string anchor.
[00371 FIG. 12 depicts another embodiment in a vertical wellbore utilizing a bi-flow connector.
[00381 FIG. 13 is the embodiment of Fig 12 except in a horizontal wellbore.
[0039] FIG. 13A is an isometric view of a bi-flow connector.
100401 FIG. 13B is a section view along line 13A-13A of FIG. 13.
100411 FIG. 13C is a top view of FIG. 13A.
100421 FIG. 13D is a section view similar to FIG. 13B except with the bi-flow connector threadably attached at a first end with a first tubular and at a second end with a second tubular.
100431 FIG. 14 is the embodiment of Fig 13 except that an alternative embodiment plunger lift system is installed in place of the downhole pump system.
100441 FIG. 15 depicts another embodiment that utilizes gas that emanates from the reservoir to lift liquids from the curved or horizontal section of the wellbore.
100451 FIG. 16 is the embodiment of Fig 15 except it is shown in a vertical wellbore.
100461 FIG. 17 is the embodiment of Fig 16 except that an alternative embodiment plunger lift system is installed in place of the downhole pump system.
DETAILED DESCRIPTION OF THE INVENTION
100471 FIG. 1 shows one example of a conventional rod pump system of the prior art in a directional or horizontal wellbore. As set out in FIG. 1, tubing 1, which contains pumped liquids 13 is mounted inside a casing 6. A pump 5 is connected at the end of tubing 1 in a seating nipple 48 nearest the reservoir 9. Sucker rods 11 are connected from the top of pump 5 and continue vertically to the surface 12. Casing 6, cylindrical in shape, surrounds and may be coaxial with tubing 1 and extends below tubing 1 and pump 5 on one end and extends vertically to surface 12 on the other end. Below casing 6 is curve 8 and lateral 10 which is drilled through reservoir 9.
100481 The process is as follows: reservoir fluids 7 are produced from reservoir 9 and enter lateral 10, rise up curve 8 and casing 6. Because reservoir fluids 7 are usually multiphase, they separate into annular gas 4 and liquids 17. Annular gas 4 separates from reservoir fluids 7 and rises in annulus 2, which is the void space formed between tubing 1 and casing 6. The annular gas 4 continues to rise up annulus 2 and then flows out of the well to the surface 12. Liquids 17 enter pump 5 by the force of gravity from the weight of liquids 17 above pump 5 and enter pump to become pumped liquids 13 which travel up tubing 1 to the surface 12. Pump 5 is not considered to be limiting, but may be any down-hole pump or pumping system, such as a progressive cavity, jet pump, or electric submersible, and the like.
100491 FIG. 2 shows one example of a conventional gas lift system of the prior art in a directional or horizontal wellbore. Referring to FIG. 2, inside the casing 6, is tubing 1 connected to packer 14 and conventional gas lift valve 22. Below casing 6 is curve 8 and lateral 10 which is drilled through reservoir 9. The process is as follows: reservoir fluids 7 from reservoir 9 enter lateral 10 and rise up curve 8 and casing 6 and enter tubing 1. The packer 14 provides pressure isolation which allows annulus 2, which is formed by the void space between casing 6 and tubing 1, to increase in pressure from the injection of injection gas 16. Once the pressure increases sufficiently in annulus 2, conventional gas lift valve 22 opens and allows injection gas 16 to pass from annulus 2 into tubing 1, which then commingles with reservoir fluids 7 to become commingled fluids 18. This lightens the fluid column and commingled fluids 18 rise up tubing 1 and then flow out of the well to surface 12.
100501 FIG. 3 shows an embodiment utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore. Referring to FIG. 3, inside casing 6, is tubing 1 which begins at surface 12 and contains internal gas lift valve 15, bushing 25, and inner tubing 21. Inner tubing 21 may be within tubing 1, such as concentric. Bushing 25 may be a section of pipe whose purpose is to threadingly connect pipe joints using both its outer diameter and its inner diameter.
Bushing 25 may have pipe threads at one or both ends of its outer diameter, and pipe threads at one or both ends of its inner diameter. Other types of bushings and connection means are also contemplated. Tubing 1 is sealing,ly engaged to packer 14. Tubing 1 and inner tubing 21 extend below packer 14 through curve 8 and into lateral 10, which is drilled through reservoir 9. Inside casing 6 and adjacent to tubing 1 is tubing 3, which contains sucker rods 11 connected to pump 5. Pump 5 is connected to the end of tubing 3 by seating nipple 48. Tubing 3 is not sealingly engaged to packer 14.
100511 The process may be as follows: reservoir fluids 7 enter lateral 10 and enter tubing I. The reservoir fluids 7 are commingled with injection gas 16 to become commingled fluids 18 which rise up chamber annulus 19, which is the void space formed between inner tubing 21 and tubing I. The commingled fluids 18 then exit through the holes in perforated sub 24.
Commingled gas 41 separates from commingled fluids 18 and rises in annulus 2, which is formed by the void space between casing 6 and tubing 1 and tubing 3. Commingled gas 41 then enters tlow line 30 at the surface 12 and enters compressor 38 to become compressed gas 33, and travels through flow line 31 to surface tank 34. The compressor 38 is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline.
[00521 Compressed gas 33 then travels through flow line 32 which is connected to actuated valve 35. This actuated valve 35 opens and closes depending on either time or pressure realized in surface tank 34. When actuated, valve 35 opens, compressed gas 33 tlows through actuated valve 35 and travels through flow line 32 and into tubing 1 to become injection gas 16. The injection gas 16 travels down tubing 1 to internal gas lift valve 15, which is normally closed thereby preventing the flow of injection gas 16 down tubing 1. A sufficiently high pressure in tubing 1 above internal gas lift valve 15 opens internal gas lift valve 15 and allows the passage of injection gas 16 through internal gas lift valve 15. The injection gas 16 then enters the inner tubing 21, and eventually commingles with reservoir fluids 7 to become commingled fluids 18, and the process begins again. Liquids 17 and commingled gas 41 separate from the commingled tluids 18 and liquids 17 fall in annulus 2 and are trapped above packer 14.
Commingled gas 41 rises up annulus 2 as previously described. As more liquids 17 are added to annulus 2, liquids 17 rise above and are gravity fed into pump 5 to become pumped liquids 13 which travel up tubing 3 to surface 12.
100531 FIG. 4 shows an alternate embodiment similar to the design in FIG. 3 except that it does not utilize the internal gas lift valve 15.
100541 FIG. 5 shows yet another alternate embodiment utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore with a different downhole configuration from FIG. 3.
Referring to FIG. 5, inside the casing 6 is tubing 1 which contains an internal gas lift valve 15 and is sealingly engaged to packer 14. Packer 14 is preferably a dual packer assembly and is connected to Y block 50 which in turn is connected to chamber outer tubing 55.
Chamber outer tubing 55 continues below casing 6 through curve 8 and into lateral 10 which is drilled through reservoir 9. Inner tubing 21 is secured by chamber bushing 22 to one of the tubular members of Y Block 50 leading to lower tubing section 37. Inner tubing 21 may be concentric with chamber outer tubing 55. The inner tubing 21 extends inside of Y block 50 and chamber outer tubing 55 through the curve 8 and into the lateral 10. The second tubing string arrangement comprises a lower section 37 and an upper section 36. The lower section 37 comprises a perforated sub 24 connected above a one way valve 28 and is then sealingly engaged in the packer 14.
10055] Perforated sub 24 is closed at its upper end and is connected to the upper tubing section 36. Upper tubing section 36 comprises a gas shroud 58, a perforated inner tubular member 57, a cross over sub 59 and tubing 3 which contains pump 5 and sucker rods 11. The gas shroud 58 is tubular in shape and is closed at its lower end and open at its upper end. It surrounds perforated inner tubular member 57, which extends above gas shroud 58 to crossover sub 59 and connects to the tubing 3, which continues to the surface 12. Above the crossover sub 59, and contained inside of tubing 3 at its lower end, is pump 5 which is connected to sucker rods 11, which continue to the surface 12. Annular gas 4 travels up annulus 2 into flowline 30 which is connected to compressor 38 which compresses annular gas 4 to become compressed gas 33. The compressor 38 is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline.
100561 Compressed gas 33 flows through flowline 31 to surface tank 34 which is connected to a second flowline 32 that is connected to actuated valve 35. This actuated valve 35 opens and closes depending on either time or pressure realized in surface tank 34. When actuated valve 35 opens, compressed gas 33 flows through actuated valve 35 and travels through flowline 32 and into tubing 1 to become injection gas 16. The injection gas 16 travels down tubing 1 to internal gas lift valve 15, which is normally closed thereby preventing the flow of injection gas 16 down tubing 1. A sufficiently high pressure in tubing 1 above internal gas lift valve 15 opens internal gas lift valve 15 and allows the passage of injection gas 16 through internal gas lift valve 15, through Y Block 50 and into chamber annulus 19, which is the void space between inner concentric tubing 21 and chamber outer tubing 55. Injection gas 16 is forced to flow down chamber annulus 19 since its upper end is isolated by chamber bushing 25.
Injection gas 16 displaces the reservoir fluids 7 to become commingled fluids 18 which travel up the inner concentric tubing 21.
[00571 Commingled fluids 18 travel out of inner concentric tubing 21 into one of the tubular members of Y Block 50, through packer 14 and standing valve 28, and then through the perforated sub 24 into annulus 2, where the gas separates and rises to become annular gas 4 to continue the cycle. The liquids 17 separate from the commingled fluids 18 and fall by the force of gravity and are trapped in annulus 2 above packer 14 and are prevented from flowing back into perforated sub 24 because of standing valve 28. As liquids 17 accumulate in annulus 2, they rise above pump 5 and are forced by gravity to enter inside of gas shroud 58 and into perforated tubular member 57 where they travel up cross-over sub 59 to enter pump 5 where they become pumped liquids 13 and are pumped up tubing 3 to the surface 12.
100581 FIG. 6 shows an alternate embodiment of the invention similar to the design in FIG. 5 except that it does not utilize the internal gas lift valve 15.
100591 FIG. 7 shows an alternate embodiment similar to FIG. 3, except that there is a downhole anchor assembly or dual string anchor 20 disposed with first tubing string 1 and installed and attached with second tubing string with on-off tool 26. Referring to FIG. 7, first tubing string 1 is inside casing 6. First tubing string 1 begins at the surface 12 and contains internal gas lift valve IS, bushing 25, perforated sub 24, and inner tubing 21. Perforated sub 24 is available from Weatherford International of Houston, Texas, among others. Tubing 1 is engaged to dual string anchor 20 and continues through it and is engaged to packer 14 and extends through it. Inner tubing 21 connects to bushing 25 and continues through perforated sub 24, dual string anchor 20, packer 14 and terminates prior to the end of tubing 1. Dual string anchor 20 is available from Kline Oil Tools of Tulsa, Oklahoma, among others. Other types of dual string anchors 20 are also contemplated. Inner tubing 21 may be within tubing 1. Tubing 1 extends through and below dual string anchor 20 and through and below packer 14 through curve 8 and into lateral 10, which is drilled through reservoir 9. Second tubing string 3 is inside casing 6 and adjacent to first tubing string 1. Second tubing string 3 contains perforated sub 23, sucker rods 11, pump 5, seating nipple 48, and on-off tool 26. Second tubing string 3 may be selectively engaged to dual string anchor 20 with on-off tool 26. On-off tool 26 is available from D&L Oil Tools of Tulsa, Oklahoma and from Weatherford International of Houston, Texas, among others.
Other types of on-off tool 26 and attachment means are also contemplated. On-off tool 26 may be disposed with perforated sub 23, which may be attached with second tubing string 3.
100601 The process for FIG. 7 is similar to that for FIG. 3. The dual string anchor 20 functions to immobilize the second tubing string 3 by supporting it with first tubing string 1.
Immobilization is important, since in deeper pump applications, the mechanical pump 5 may induce movement to second tubing string 3 which may in turn cause wear on the tubulars.
Movement may also cause the mechanical pump operation to cease or become inefficient. On-off tool 26 allows the second tubing string 3 to be selectively connected or disconnected from the dual string anchor 20 without disturbing the first tubing string 1. The dual string anchor 20 minimizes inefficiencies in the pump and costly workovers to repair wear on the tubing strings.
This movement is caused by the movement induced upon the second tubing string by the downhole pumping system.
[00611 FIG. 8 shows another alternate embodiment similar to the design in FIG.
7 except that it does not utilize internal gas lift valve 15.
100621 FIG. 9 shows another alternate embodiment similar to the design of FIG.
7, except that FIG. 9 includes one-way valve 28 disposed on first tubing string 1 below packer 14. Referring to FIG. 9, when pressure conditions are favorable, one-way valve 28 opens to allow reservoir gas 27 to pass into chamber annulus 19. One-way valve 28 may be a reverse flow check valve available from Weatherford International of Houston, Texas, among others.
Other types of one-way valves 28 are also contemplated. Although only one one-valve 28 is shown, it is contemplated that there may be more than one one-way valve 28 for all embodiments. One-way valve 28 may be threadingly disposed with a carrier such as a conventional tubing retrievable mandrel or a gas lift mandrel. Other connection types, carriers, and mandrels are also contemplated.
[00631 One-way valve 28 functions to allow fluids to flow from outside to inside the device in one direction only. In FIGS. 9-14, one-way valve 28 may be placed in the first tubing string 1 below the packer 14 to vent trapped pressure below the packer 14 into the first tubing string 1.
In a vertical well application, this venting may assist the optimum functioning of the artificial lift system. One-way valve 28 has at least two functions: (1) it provides a pathway to the surface for reservoir gas 27 trapped below packer 14, and (2) it leads to production increases by reducing back pressure on the reservoir. As can now be understood, one-way valve 28 may be positioned at a location on first tubing string 1, such as below packer 14, that is different than the location where injected gas 16 initially commingles with the reservoir fluids where inner tubing 21 ends.
Injected gas 16 may initially commingle with reservoir fluids 7 at a first location, and one-way valve 28 may be disposed on first tubing string 1 at a second location. One-way valve 28 may be disposed above reservoir 9, although other locations are contemplated. One-way valve 28 allows the venting of trapped fluids, and allows flow in only one direction.
100641 FIG. 10 shows the embodiment of FIG. 9 in a completely vertical wellbore.
[00651 As can now be understood, dual string anchor or dual tubing anchor 20 with on-off tool 26 and one way-valve 28 may be used independently, together, or not at all.
For all embodiments in deviated, horizontal, or vertical wellbore applications, there may be (1) gas lift valve 15, dual string anchor 20, and one-way valve 28 below packer 14, (2) no gas lift valve 15, no dual string anchor 20, and no one-way valve 28 below packer 14, or (3) any combination or permutation of the above. Surface tank 34 and actuated valve 35 are also optional in all the embodiments.
[00661 FIG. 11 is an embodiment similar to FIG 10 in which pump 5 and sucker rods 11 have been replaced with an alternative embodiment plunger lift system, and there is no surface tank 34 and no one-way valve 28. Referring to FIG 11, the process is as follows.
Initially, actuated valve 37 is open at surface 12, which allows flow from tubing 3 to surface 12.
Actuated valve 35 is open and actuated valve 36 is closed. Supply gas 46, which may emanate from the well or a pipeline, is compressed by compressor 38 and compressed gas 33 flows through flow line 31, through actuated valve 35 and flow line 32, and into tubing Ito become injection gas 16, which then flows down tubing 1, through gas lift valve 15, and through inner tubing 21. At the end of inner tubing 21, injection gas 16 combines with reservoir fluids 7 to become commingled fluids 18, which rise up chamber annulus 19 and flow through perforated sub 24 into annulus 2.
Liquids 17 fall to the bottom of annulus 2.
10067J As more liquids are added in annulus 2, they eventually rise above plunger 5 and into tubing 3 and rise above perforated sub 24, which may cause the injection pressure to rise which signals actuated valve 35 to close, actuated valve 39 to open, and actuated valve 37 to close.
Compressed gas 33 then flows through actuated valve 36 and through flow line 30, and into annulus 2 to become injection gas 16. When a sufficient volume of injection gas 16 has been added to annulus 2, the pressure in annulus 2 rises sufficiently to signal actuated valve 37 to open, actuated valve 36 to close, and actuated valve 35 to open. The pressure differential lifts plunger 45 off of seating nipple 48 and rises up tubing 3 and pushes liquids 17 to surface 12.
Some injection gas 16 also flows to surface 12 via tubing 3. Once the pressure on tubing 3 drops sufficiently, plunger 45 falls back down to seating nipple 48 and the process begins again. Other sequences of the timing of the opening and closing of the actuated valves are contemplated.
Surface tank 34 may also be utilized.
[0068J FIG. 12 is another embodiment and utilizes an outer and inner tubing arrangement, such as concentric, incorporating a novel bi-flow connector 43 in a vertical wellbore. The bi- flow connector 43 is shown in detail in FIGS. 13A-13D and discussed in detail below. FIGS. 13 is similar to FIG. 12 except in a horizontal wellbore. Although FIG. 13 is discussed below, the discussion applies equally to FIG. 12. In FIG. 13, first tubing string 1 begins at surface 12 and is installed inside casing 6, contains bi-flow connector 43, bushing 25, one way valve 29, and is sealingly engaged to packer 14. Mud anchor 40 may be connected to bi-flow connector 43 to act as a reservoir for particulates that fall out of liquids 17, and to isolate the injection gas 16 from liquids 17. Mud anchor 40 is a tubing with one end closed and one end open, and is available from Weatherford International of Houston, Texas, among others. First tubing string 1 continues below packer 14 and contains one way valve 28 and continues until it terminates in curve 8 or lateral 10, or for FIG. 12 in or below reservoir 9. Within first tubing string 1 is second tubing string 21, which is also sealingly engaged to bushing 25 and continues down through packer 14 and may terminate prior to the end of first tubing string I. Third tubing string 3 is within first tubing string, and begins at surface 12 and terminates in on-off tool 26. On-off tool 26 allows third tubing string 3 to be selectively engaged to first tubing string 1. On-off tool 26 is sealingly engaged to bi-flow connector 43. Contained inside first tubing string 3 are sucker rods 11, pump and seating nipple 48. Sucker rods 11 are connected to pump 5 which is selectively engaged into seating nipple 48. Seating nipple 48 is available from Weatherford International of Houston, Texas, among others.
100691 As shown in FIGS. 13A-13D, bi-tlow connector 43 is a cylindrically shaped body with a central bore 112 extending from a first end 105 to a second end 107 and having a thickness 109.
Vertical or first channels 102 pass through the thickness 109 of the bi-flow connector 43 from the first end 105 to the second end 107. Horizontal or second channels 100 pass from the side surface 111 through the thickness 109 of the bi-flow connector 43 to the central bore 112.
Although shown vertical and horizontal, it is also contemplated that first channels may not be vertical and second channels may not be horizontal. Different numbers and orientations of channels are contemplated. The first channels 102 and second channels 100 do not intersect.
Threads 104, 108 are on the side surface 111 of the bi-flow connector 43 adjacent its first and second ends 105, 107. There may also be inner threads 106, 110 on the inner surface of the central bore 112 adjacent the first and second ends. As shown in FIGS. 12-13, the mud anchor 40 is attached with the inner threads 110, and the first tubing string 1 is attached with the outer threads 104, 108. In FIG. 13D, the threaded connection between the bi-flow connector 43 between upper tubular 114 and lower tubular 116 is similar to the connection in FIG. 13 between the hi-flow connector 43 and first tubing string I.
[00701 Returning to FIG. 13, the process may be as follows. Injection gas 16 travels down annulus 47 and passes vertically through bi-flow connector 43 and continues down through bushing 25, packer 14, second tubing string 21 and out into first tubing string 1 where it commingles with reservoir fluids 7 to become commingled fluids 18. Reservoir gas emanates from reservoir 9 and may travel through one way valve 28 and become part of commingled fluids 18, which rise up annulus 19 and travel through one way valve 29 and then separate into liquids 17 and commingled gas 41. Liquids 17 may enter horizontally through hi-flow connector 43 and up to pump 5 where they become pumped liquids 13 and are pumped to surface 12.
Commingled gas 41 rises up annulus 2 to surface 12.
100711 As can now be understood, the bi-flow connector 43 allows downward injection gas to pass vertically through the tool, while simultaneously allowing reservoir liquids to pass horizontally through the tool, without commingling the reservoir liquids with the downwardly flowing injection gas. The bi-flow connector 43 also allows the inner tubing string, such as third tubing string 3, to be selectively engaged to the outer tubing string, such as first tubing string 1.
The bi-flow connector 43 may be used in small casing diameter wellbores in which the installation of two side by side or adjacent tubing strings is impractical or impossible. The bi-tlow connector 43 is advantageous to wells that have a smaller diameter casing. Other non-concentric tubing arrangement embodiments may require larger casing sizes. A
plunger system is also contemplated in place of the downhole pump.
100721 FIG. 14 is the same embodiment as FIG. 13 except that an alternative embodiment plunger lift system is installed in place of the downhole pump system. A pump and a plunger are both fluid displacement devices.
100731 FIG. 15 is another embodiment using only reservoir gas to lift the reservoir liquids from below the downhole pump to above the downhole pump. This embodiment is similar to FIG. 13, but no inner tubing, such as third tubing string 3, is needed to house the downhole pump and no external injection gas is needed. It may also incorporate a one way valve 28 in the tubing string to prevent wellbore liquids from falling back down the wellbore. The one way valve 28 allows the liquids to be trapped above the packer until the pump can lift them to the surface. The smaller diameter of the inner tubing efficiently lifts reservoir fluids by forcing the reservoir gas into a smaller cross-sectional area whereby the gas is not allowed to rise faster than the reservoir liquids. Due to the smaller tubing size, a relatively small amount of reservoir gas can lift reservoir liquids the relatively short distance from the end of the tubing to the one way valve.
100741 Referring to FIG. 15, first tubing string 1 begins at surface 12 and contains seating nipple 48, upper perforated sub 23, blank sub 42, lower perforated sub 24, one way valve 39, on-off tool 26, packer 14, bushing 25 and terminates in curve 8 or lateral 10. Seating nipple 48, blank sub 42, perforated subs 23, 24, on-off tool 26, packer 14, one way valve 39, and bushing 25 are all available from Weatherford International of Houston, Texas, among others.
Connected to seating nipple 48 is pump 5 which is connected to sucker rods 11 which continue up to surface 12. Connected to bushing 25 is second tubing string 21 which is connected to one way valve 28, and continues down the wellbore and may terminate prior to the end of tubing 1.
[00751 The process may be as follows. Reservoir fluids 7 emanate from reservoir 9 and enter lateral 10 and then enter first tubing string 1 and second tubing string 21.
Gas in reservoir fluids 7 expand inside second tubing string 21 and lift reservoir fluids 7 up and out of second tubing string 21 into first tubing string 1, through on-off tool 26, through one way valve 39 and out of lower perforated sub 24 and into annulus 2. Reservoir fluids 7 separate into liquids 17 and annular gas 4. Liquids 17 enter into upper perforated sub 23 and then enter into pump 5 where they become pumped liquids 13 and are pumped to surface 12 via tubing 1.
Annular gas 4 rises up annulus 2 to surface 12.
100761 FIG. 16 is the embodiment of FIG. 15 except in a vertical wellbore.
100771 FIG. 17 is the embodiment of FIG. 16 except that a plunger has been installed in place of the sucker rods and pump. The plunger may be operated merely by the periodic opening and closing of the first tubing string 1 to the surface or it may be operated by the periodic or continuous injection of gas down the annulus combined with the periodic opening and closing of the first tubing string 1 to the surface. Both methods will force the plunger and liquids above it to the surface. This embodiment is much less expensive than installing a downhole pump. This design is advantageous for wells that have sufficient reservoir energy and gas production to lift liquids from below the downhole pump to above the downhole pump, yet still require artificial lift equipment to lift these liquids to the surface. This embodiment is less costly to install since no injection gas from the surface is required. Subsequently there is no gas injection tubing, no surface tank, no actuated valve, no compressor, and no dual string anchor. It will also accommodate wellbores with smaller casing diameters.
[00781 The embodiment of FIGS. 15-16 is advantageous for wells that have sufficient reservoir energy and gas production to lift liquids from below the downhole pump to above the downhole pump, yet still require artificial lift equipment to lift these liquids to the surface. This embodiment is less costly to install since no injection gas from the surface is required. There does not have to be any gas injection tubing, surface tank, actuated valve, compressor, or dual string anchor. It will also accommodate wellbores with smaller casing diameters. The embodiment of FIG. 17 is even less expensive because there does not have to be any downhole pump and related equipment.
100791 An advantages of all embodiments is a lower artificial lift point and better recovery of hydrocarbons. There is better gas and particulate separation in all embodiments. In FIGS. 3-11, the entry point for the commingled fluids is above the intake of the pump or other fluid displacement device, which helps break out any gas in the fluids since gravity will segregate the gas from the liquids. The same is true for particulates since there is a large reservoir for them to collect in below the pump. In FIGS. 12-17, the gas is discouraged from entering the perforated subs because of gravity separation.
100801 Because many varying and different embodiments may be made within the scope of the invention concept taught herein which may involve many modifications in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense.
Claims (29)
1. An artificial lift system in a wellbore extending from the surface to a reservoir having reservoir fluids, comprising:
a casing in the wellbore;
a first tubing string sealingly engaged with and extending through a packer disposed in said casing;
a bi-flow connector attached in said first tubing string;
a second tubing string disposed in a portion of said first tubing string below said bi-flow connector; and a third tubing string disposed in a portion of said first tubing string above said bi-flow connector and containing a fluid displacement device configured to move reservoir fluids to the surface;
wherein said first tubing string is configured to transport a pressured gas downwardly from the surface through said bi-flow connector to commingle with and lift the reservoir fluids through an annulus between said casing and said first tubing string;
wherein an end of said third tubing string is connected with said bi-flow connector; and wherein said bi-flow connector is configured to allow both the downward pressured gas and the lifted reservoir fluids to simultaneously pass through it without contacting each other.
a casing in the wellbore;
a first tubing string sealingly engaged with and extending through a packer disposed in said casing;
a bi-flow connector attached in said first tubing string;
a second tubing string disposed in a portion of said first tubing string below said bi-flow connector; and a third tubing string disposed in a portion of said first tubing string above said bi-flow connector and containing a fluid displacement device configured to move reservoir fluids to the surface;
wherein said first tubing string is configured to transport a pressured gas downwardly from the surface through said bi-flow connector to commingle with and lift the reservoir fluids through an annulus between said casing and said first tubing string;
wherein an end of said third tubing string is connected with said bi-flow connector; and wherein said bi-flow connector is configured to allow both the downward pressured gas and the lifted reservoir fluids to simultaneously pass through it without contacting each other.
2. The artificial lift system of claim 1, wherein said displacement device is a pump.
3. The artificial lift system of claim 1, wherein said displacement device is a plunger.
4. The artificial lift system of claim 1, further comprising a first one-way valve attached in said first tubing string above said packer.
5. The artificial lift system of claim 4, further comprising a second one-way valve attached in said first tubing string below said packer.
6. The artificial lift system of claim 1, wherein said bi-flow connector comprises a cylindrical body having a thickness, a first end, a second end, a central bore from said first end to said second end, a side surface, a first channel disposed through said thickness from said first end to said second end, and a second channel disposed through said thickness from said side surface to said central bore; and wherein said first channel and said second channel do not intersect.
7. The artificial lift system of claim 6, wherein there are more than one channel disposed through said thickness from said first end to said second end; and wherein there are more than one channel disposed through said thickness from said side surface to said central bore.
8. The artificial lift system of claim 1, wherein said third tubing string is connected with said bi-flow connector with an on-off tool and a mud anchor.
9. The artificial lift system of claim 8, wherein said mud anchor comprises a tubular with a first end open and a second end closed.
10. The artificial lift system of claim 1, wherein an end of said second tubing string is connected in said first tubing string with a bushing above said packer.
11. A method for producing reservoir fluids with an artificial lift system from a wellbore extending from the surface to a reservoir, comprising:
positioning a first tubing string though a packer disposed in a casing in the wellbore;
injecting a pressured gas from the surface in said first tubing string downwardly through a bi-flow connector attached with said first tubing string;
moving the pressured gas downwardly though a second tubing string attached with said first tubing string above said packer;
commingling the pressured gas with the reservoir fluids;
lifting the commingled pressured gas and reservoir fluids through an annulus between the casing and the first tubing string;
moving the lifted reservoir fluids through said bi-flow connector during the step of injecting the pressured gas downwardly through said bi-flow connector without contacting the lifted reservoir fluids with the downward pressured gas; and displacing said reservoir fluids to the surface with a displacement device disposed in a third tubing string positioned in said first tubing string above said bi-flow connector.
positioning a first tubing string though a packer disposed in a casing in the wellbore;
injecting a pressured gas from the surface in said first tubing string downwardly through a bi-flow connector attached with said first tubing string;
moving the pressured gas downwardly though a second tubing string attached with said first tubing string above said packer;
commingling the pressured gas with the reservoir fluids;
lifting the commingled pressured gas and reservoir fluids through an annulus between the casing and the first tubing string;
moving the lifted reservoir fluids through said bi-flow connector during the step of injecting the pressured gas downwardly through said bi-flow connector without contacting the lifted reservoir fluids with the downward pressured gas; and displacing said reservoir fluids to the surface with a displacement device disposed in a third tubing string positioned in said first tubing string above said bi-flow connector.
12. The method of claim 11, wherein said displacement device is a pump.
13. The method of claim 11, wherein said displacement device is a plunger.
14. The method of claim 11, further comprising the step of:
moving the comingled pressured gas and reservoir fluids through a first one-way valve attached in said first tubing string above said packer.
moving the comingled pressured gas and reservoir fluids through a first one-way valve attached in said first tubing string above said packer.
15. The method of claim 14, further comprising the step of:
moving the comingled pressured gas and reservoir fluids through a second one-way valve attached in said first tubing string below said packer.
moving the comingled pressured gas and reservoir fluids through a second one-way valve attached in said first tubing string below said packer.
16. The method of claim 11, wherein said bi-flow connector comprises a cylindrical body having a thickness, a first end, a second end, a central bore from said first end to said second end, a side surface, a first channel disposed through said thickness from said first end to said second end, a second channel disposed through said thickness from said side surface to said central bore;
and wherein said first channel and said second channel do not intersect.
and wherein said first channel and said second channel do not intersect.
17. The artificial lift system of claim 16, wherein there are more than one channel disposed through said thickness from said first end to said second end; and wherein there are more than one channel disposed through said thickness from said side surface to said central bore.
18. An apparatus for use in a wellbore extending from the surface into a reservoir containing reservoir fluids, comprising:
a cylindrical body having a thickness, a first end, a second end, a central bore from said first end to said second end, and a side surface;
wherein a first channel is disposed through said thickness from said first end to said second end;
wherein a second channel is disposed through said thickness from side surface to said central bore;
wherein said first channel and said second channel do not intersect;
wherein said first channel is configured to pass pressured gas from the surface used to commingle with and lift the reservoir fluids; and wherein said second channel is configured to pass the lifted reservoir fluids.
a cylindrical body having a thickness, a first end, a second end, a central bore from said first end to said second end, and a side surface;
wherein a first channel is disposed through said thickness from said first end to said second end;
wherein a second channel is disposed through said thickness from side surface to said central bore;
wherein said first channel and said second channel do not intersect;
wherein said first channel is configured to pass pressured gas from the surface used to commingle with and lift the reservoir fluids; and wherein said second channel is configured to pass the lifted reservoir fluids.
19. The artificial lift system of claim 18, wherein there are more than one channel disposed through said thickness from said first end to said second end; and wherein there are more than one channel disposed through said thickness from said side surface to said central bore.
20. A method for moving reservoir fluids in a wellbore to the surface, comprising the steps of:
positioning a cylindrical body in the wellbore; wherein said cylindrical body having a thickness, a first end, a second end, a central bore from said first end to said second end, a side surface, a first channel disposed through said thickness from said first end to said second end, a second channel disposed through said thickness from side surface to said central bore; and wherein said first channel and said second channel do not intersect;
moving a pressured gas downwardly from the surface through said first channel;
and moving the reservoir fluids through said second channel.
positioning a cylindrical body in the wellbore; wherein said cylindrical body having a thickness, a first end, a second end, a central bore from said first end to said second end, a side surface, a first channel disposed through said thickness from said first end to said second end, a second channel disposed through said thickness from side surface to said central bore; and wherein said first channel and said second channel do not intersect;
moving a pressured gas downwardly from the surface through said first channel;
and moving the reservoir fluids through said second channel.
21. The artificial lift system of claim 20, wherein there are more than one channel disposed through said thickness from said first end to said second end; and wherein there are more than one channel disposed through said thickness from said side surface to said central bore.
22. A system for removing reservoir fluids, comprising:
a wellbore extending from the surface to a reservoir having reservoir fluids;
a casing in the wellbore;
a first tubing string sealingly engaged with and extending through a packer disposed in said casing;
a blank sub between an upper perforated sub and a lower perforated sub connected in said first tubing string;
a second tubing string disposed in a portion of said first tubing string below said lower perforated sub;
a fluid displacement device disposed in said first tubing string above said upper perforated sub and configured to move reservoir fluids to the surface;
wherein said second tubing string is configured to transport the reservoir fluids to the first tubing string;
wherein said lower perforated sub is configured to pass the reservoir fluids from said first tubing string to an annulus between said casing and said first tubing string;
and wherein said upper perforated sub is configured to pass the reservoir fluids from said annulus to said first tubing string.
a wellbore extending from the surface to a reservoir having reservoir fluids;
a casing in the wellbore;
a first tubing string sealingly engaged with and extending through a packer disposed in said casing;
a blank sub between an upper perforated sub and a lower perforated sub connected in said first tubing string;
a second tubing string disposed in a portion of said first tubing string below said lower perforated sub;
a fluid displacement device disposed in said first tubing string above said upper perforated sub and configured to move reservoir fluids to the surface;
wherein said second tubing string is configured to transport the reservoir fluids to the first tubing string;
wherein said lower perforated sub is configured to pass the reservoir fluids from said first tubing string to an annulus between said casing and said first tubing string;
and wherein said upper perforated sub is configured to pass the reservoir fluids from said annulus to said first tubing string.
23. The artificial lift system of claim 22, wherein said displacement device is a pump.
24. The artificial lift system of claim 22, wherein said displacement device is a plunger.
25. The artificial lift system of claim 22, further comprising a one-way valve attached in said second tubing string.
26. A method for producing reservoir fluids from a wellbore extending from the surface to a reservoir, comprising:
positioning a first tubing string though a packer disposed in a casing in the wellbore;
moving the reservoir fluids through a second tubing string disposed in a portion of said first tubing string;
passing the reservoir fluids from said first tubing string through a lower perforated sub attached in said first tubing string to an annulus between said first tubing string and the casing;
positioning a first tubing string though a packer disposed in a casing in the wellbore;
moving the reservoir fluids through a second tubing string disposed in a portion of said first tubing string;
passing the reservoir fluids from said first tubing string through a lower perforated sub attached in said first tubing string to an annulus between said first tubing string and the casing;
27 passing the reservoir fluids from said annulus through an upper perforated sub attached in said first tubing string to said first tubing string; and displacing said reservoir fluids to the surface with a displacement device disposed in said first tubing string above said upper perforated sub.
27. The method of claim 26, wherein said displacement device is a pump.
27. The method of claim 26, wherein said displacement device is a pump.
28. The method of claim 26, wherein said displacement device is a plunger.
29. The method of claim 26, further comprising the step of:
moving the reservoir fluid through a one-way valve attached with said second tubing string.
moving the reservoir fluid through a one-way valve attached with said second tubing string.
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| PCT/US2012/047178 WO2013016097A2 (en) | 2011-07-25 | 2012-07-18 | System and method for production of reservoir fluids |
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| RU2485293C1 (en) * | 2011-12-22 | 2013-06-20 | Общество с ограниченной ответственностью Научно-производственная фирма "Пакер" | Method of borehole transfer and unit for transfer of liquid from upper well formation to lower one with filtration |
| US9951592B2 (en) * | 2013-03-08 | 2018-04-24 | Kurt Carleton | Apparatuses and methods for gas extraction from reservoirs |
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| US20160108709A1 (en) | 2016-04-21 |
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